In general, poor vertical conformance of fluids injected into or produced from a subterranean formation occurs where the formation exhibits a lack of vertical homogeneity. For example, while hydrocarbon-bearing subterranean formations exhibit relatively homogeneous horizontal properties near a well bore, horizontal stratification can occur at a distance from the well bore via cross-bedding between subterranean zones, beds, channels or vugs of varying permeabilities. Fluid injected into or produced from a well penetrating the formation tends to preferentially channel or finger into areas of relatively high permeability, thus resulting in extremely poor vertical conformance and flow profiles. Further exemplary, relatively highly permeable zones or beds may be vertically juxtaposed to zones or beds of relatively low permeability at the subterranean location where fluids are to be injected or produced via a well bore, i.e. the near well bore environment. Fluid injected into or produced from the subterranean hydrocarbon-bearing formation will preferentially flow through the zones or beds of relatively high permeability resulting in a relatively high residual hydrocarbon content in the remaining zones, beds, channels or vugs of relatively low permeability.
Several prior art processes have been proposed to alleviate such preferential channeling or fingering, and thus, improve conformance and injection and/or production flow profiles. High molecular weight organic polymers and cross-linking agents, such as polyvalent cations, have been sequentially injected into a subterranean hydrocarbon-bearing formation. These sequentially injected fluids predominantly finger or channel into areas of relatively high permeability wherein the high molecular weight organic polymers are cross-linked and gelled. This gel plugs relatively highly permeable areas distant from the well bore and improves conformance and flow profiles of injected and/or produced fluids. U.S. Pat. Nos. 3,805,893 and 3,871,452 to Sarem involve processes which utilize the sequential injection of a dilute aqueous alkaline metal silicate solution, such as an aqueous solution of sodium and potassium orthosilicate, a spacer plug of relatively soft water, and an aqueous slug containing a reagent, such as, calcium or magnesium, which will react with the alkaline alkali metal silicate. The orthosilicate and the reagent react at a location distant from the well bore and form a relatively insoluble precipitate. As these injection fluids tend to channel into areas of relatively high permeability, such precipitates tend to plug the highly permeable areas distant from the well bore, and thus, improve conformance and flow profiles. U.S. Pat. No. 3,658,131 to Biles discloses another process for selectively plugging highly permeable channels in a hydrocarbon-bearing formation by injecting a fresh water slug as a spacer for a subsequently injected aqueous solution containing 10-20 weight percent sodium silicate. The silicate will react with calcium cations present in formation water to form a relatively insoluble precipitate. U.S. Pat. No. 3,837,400 to Martin discloses plugging permeable channels in a water flooded oil zone by injecting a sodium hydroxide solution which is isolated from connate water by a slug of water low in metallic ions. At a distance from the well bore, the sodium hydroxide penetrates the water isolation slug and reacts with various metallic ions in the connate water, such as magnesium and calcium, to form low solubility precipitates which will plug the channels. U.S. Pat. No. 2,272,672 to Kennedy relates to a process for minimizing by passing of water encountered in water flooding an oil field. One embodiment of the process involves the successive injection of an alkali and magnesium sulphate or chloride. The alkali and the magnesium sulphate or chloride reacts in situ to form a precipitate which plugs the more permeable strata. U.S. Pat. No. 2,402,588 to Andreson discloses a process for selectively plugging highly permeable strata of a subterranean hydrocarbon-bearing formation by injecting therein an aqueous alkaline solution of sodium silicate and a reagent, such as a weak acid, which slowly reduces the alkalinity of the solution to cause formation of a precipitate or gel. U.S. Pat. No. 3,530,937 to Bernard discloses a process for reducing the permeability of the more highly permeable strata of a subterranean hydrocarbon-bearing formation wherein two aqueous solutions are successively injected into the formation, each solution containing an agent which will react to form a plugging precipitate when brought into contact with each other in the reservoir. An aqueous spacing medium is injected between the two aqueous solutions. Examples of the two solutions are a solution of a water-soluble salt, including calcium and magnesium, and an alkaline solution, such as sodium hydroxide or sodium silicate. Where the formation contains mineral substances capable of reacting with either agent to form a precipitate, care is taken to select an agent which is inert to such mineral substances. U.S. Pat. No. 2,747,670 to King, et al discloses a similar process which involves the sequential injection of an aqueous salt solution, an inert spacing medium, e.g. water on brine, and an aqueous alkali solution into a subterranean formation to improve the permeability profile thereof. Calcium or magnesium salts and sodium hydroxide or sodium carbonate are preferably employed in the successively injected aqueous solutions.
All of these prior art processes involve the use of an aqueous spacer between sequentially injected aqueous fluids. As these fluids preferentially channel or finger into the areas of relatively high permeability, the trailing fluid eventually penetrates the water spacer and reacts with the initially injected fluid or the formation water to form a plugging precipitate at a substantial distance from the well bore. These proposed art processes have not proved altogether satisfactory. The processes which involve the use of high molecular weight polymers or resins tend to be expensive and therefore cost ineffective, and none of these prior art processes have proved effective in improving vertical conformance and flow profiles of injected and/or produced fluids in the environment near a well bore. As radial flow of fluids injected into or produced from a well bore is predominantly influenced by the near well bore environment, failure of the prior art processes to improve vertical conformance and flow profiles in the near well bore environment has resulted in relatively poor vertical conformance and flow profiles of injected and/or produced fluids in the subterranean environment.
As hereinafter detailed, it has been discovered that these prior art processes which employ sequentially injected aqueous fluids fail to improve vertical conformance and flow profiles to any substantial degree due to the lack of mixing, and therefore, formation of precipitates in relatively high permeable areas in the environment near the well bore penetrating the formation. For relatively short radial distances away from the well bore e.g. about 2.5 centimeters to about 9 meters, subterranean formations exhibit relatively homogeneous horizontal characteristics. These prior art processes rely on fingering of sequentially injected aqueous fluids throughout a substantial distance within an area of relatively high permeability to allow the injected fluids to penetrate or disperse through the aqueous spacer slug and mix. As such, sequentially, continuously injected aqueous fluids separated by an aqueous spacer slug do not mix to any substantial degree in relatively highly permeable areas in the near well bore environment, and therefore do not improve conformance and flow profiles of fluids injected into or produced from such environment. Thus, a need exists for a process which results in the formation of large amounts of insoluble, plugging precipitates in relatively highly permeable zones in the near well bore environment to improve vertical conformance and flow profiles of injected or produced fluids.